Weighted fluid loss control pill for completion &amp; workover operations

ABSTRACT

Novel completion fluid compositions for fluid loss control during completion and workover operations conducted on a wellbore penetrating a subterranean formation are disclosed. In particular, the composition is a weighted brine fluid having a polymetaphosphate composition, a biopolymer suspension agent, and a fluid loss control additive. These novel compositions provide a means to temporarily seal a wellbore communicating with a subterranean formation to enable completion or workover operations to be performed, after which the composition can be removed by contact with an acidic composition.

PRIOR RELATED APPLICATIONS

This application is the Non-Provisional Patent Application, which claimsbenefit of priority to U.S. Provisional Application No. 62/882,214,filed Aug. 2, 2019 and U.S. Provisional Application No. 62/924,280,filed on Oct. 22, 2019, the contents of which are incorporated herein byreference in their entirety.

FEDERALLY SPONSORED RESEARCH STATEMENT

Not applicable.

REFERENCE TO MICROFICHE APPENDIX

Not applicable.

FIELD OF THE DISCLOSURE

The disclosure generally relates to completion fluids and methods of usein hydrocarbon reservoirs, and more particularly to the use of readilyremovable additives in completion fluids.

BACKGROUND OF THE DISCLOSURE

Oil and gas companies are challenged to produce as much of theirhydrocarbon reserves as possible in an efficient and cost-effectivemanner. As such, the completion and production process rely on the useof treatment fluids designed to resolve specific reservoir conditionsthrough the use of one or more additives to increase hydrocarbonproduction. Unfortunately, these treatment fluids are lost to theformation, reducing the efficiency of the treatment.

During the completion phase, for example, weighted completion fluids areused to prevent blowouts during completion procedures and wellworkovers. When injected, the hydrostatic head of the weightedcompletion fluid within the wellbore exerts a greater pressure on thesubterranean formation than the fluid pressures within the formation.This positive pressure towards the subterranean formation, whilepermitting control of the wellbore, causes the completion fluid to flowinto vugs, pore spaces, and natural or manmade fractures in theformations, as well as other flow paths such as wellbore.

The loss of these weighted completion fluids is highly undesirablebecause completion fluids are very expensive. If high losses areexperienced, the reservoir can become too cost inefficient to producehydrocarbons. Additionally, the weighted completion fluids must berelatively viscous to suspend weighting materials included therein. Whenthese viscous fluids are lost into formations containing hydrocarbons,the permeabilities of the formations are reduced, which in turn reducesthe ability to produce hydrocarbons from the formations.

As such, one or more fluid loss control agents, in the form of gels orparticulate matter, are included in the weighted completion fluid.Particulate material has been employed to temporarily bridge/seal/plugcertain flow paths in the formations, such that these flow paths can bere-opened for subsequent operations. Similarly, gel fluid lossadditives, or gel “pills”, made from various natural polymers such asguar gum, hydroxyethylcellulose and their derivatives, have been used tocontrol fluid loss by sealing openings. The pills are then removed byinternal or external gel breaking chemicals to allow for production ofhydrocarbon fluids from the formation.

There is a risk, however, of forming impenetrable plugs of fluid losscontrol agents in the perforations that cannot subsequently be removed.Soluble solid particulates bridge on a formation face and fill theperforations or fractures extending from within the wellbore into theformation. Though these particulates block openings to prevent fluidloss, circulated solvents that target the soluble particulates forremoval will have limited contact with the particulates in theformation. As these solvents cannot penetrate the perforations orfractures, they cannot remove the particulates from the formation,resulting in an impenetrable plug extending from the wellbore into theperforations. This can stop or drastically reduce hydrocarbon productionfrom the formation, and require costly reperforation and other remedialprocedures to reopen the fractures.

Thus, there is a need for the development of improved compositions thatcan block openings of various sizes to prevent fluid loss, but areeasily removed from all openings, including perforations extending fromthe wellbore. Ideally, these compositions are capable of being used withweighted fluids and do not affect the permeability of the reservoir.

SUMMARY OF THE DISCLOSURE

Described herein are compositions of treatment fluids and methods oftheir use in hydrocarbon reservoirs. Particularly, the compositions areweighted completion fluids comprising a polymetaphosphate composition, abiopolymer suspension agent, and a fluid loss control additive. Thepolymetaphosphate and fluid loss control additive temporarily blockopenings such as those in a wellbore communicating with a subterraneanformation, or gravel pack screens, to enable completion or workoveroperations to be performed. Thereafter, the polymetaphosphate and fluidloss control additive can be removed by dissolution after a few minutesof contact with an acidic fluid circulated through the wellbore. Thisallows for quick removal compared to other fluid loss pills andadditives that require six or more hours of soaking in acidic solutions.

Additionally, the treatment fluids disclosed herein can contain optionaladditives that are used in completion fluids but are not acidic. Theseoptional additives include, but are not limited to salts, pH controladditives, surfactants, breakers, biocides, additional fluid losscontrol agents, stabilizers, chelating agents, scale inhibitors, gases,mutual solvents, particulates, binders, proppants, corrosion inhibitors,oxidizers, reducers, and any combination thereof. As long as theseoptional additives do not lower the pH of the completion fluid below 4,the optional additives will not affect the ability of thepolymetaphosphate composition and fluid loss control additive to form aphysical barrier. This allows the presently disclosed compositions to beutilized in a variety of applications, in both reservoir and wellboreoperations.

The present compositions and methods include any of the followingembodiments in any combination(s) of one or more thereof:

A treatment fluid comprising a weighted brine, a biopolymer suspensionagent for increasing the viscosity of the weighted brine to form acarrier fluid, a polymetaphosphate composition, and a fluid loss controladditive. In an embodiment, an initial viscosity is that of fresh waterat standard conditions (1 centipoise). In an embodiment, salt is addedand the viscosity may increase between one or two centipoise for saltslike sodium chloride. In other embodiments, the viscosity may be furtherincreased by 3, 4, 5, 6, 7, 8, or 9 centipoise when for examplesaturated solutions of calcium chlorides are used. In still furtherembodiments, polymers (guar, xanthan, hydroxyethylcellulose, and thelike) may be added, depending on the concentration, in order to increasethe viscosity in the range of from 10 to 100 centipoise. In stillalternatively and further embodiments, crosslinked polymers (such asguar, crosslinked with boron) may be used to increase the viscosity to100 to 1000 centipoise.

A method of plugging an opening in a reservoir comprising injecting atreatment fluid into a subterranean formation, wherein the treatmentfluid comprises a weighted brine carrier fluid, a biopolymer suspensionagent for increasing the viscosity of the weighted brine carrier fluid,a particulate polymetaphosphate composition, and a fluid loss controladditive. At least one opening in the subterranean formation is pluggedwith the particulate polymetaphosphate composition. The fluid losscontrol agent then plugs at least one gap between the particles of theparticulate polymetaphosphate composition or a gap between theparticulate polymetaphosphate composition and the opening. Once theopenings are plugged and sealed, one or more additional operations thatuse a fluid in the subterranean formation can be performed, wherein thefluid is not lost through the plugged openings. Once the operations arecompleted, the openings can be unplugged by circulating an aqueousacidic fluid through the wellbore to remove the particulatepolymetaphosphate composition and the fluid loss control additive.Fluids can then flow through the now un-plugged openings. The openingscan be perforations, fractures, vugs, or pore spaces in the reservoir,including the wellbore, or openings in screens such as gravel packscreens,

A method of plugging a gravel pack screen in a reservoir comprisinginjecting a treatment fluid into a subterranean formation having atleast one gravel pack screen, wherein the treatment fluid comprises aweighted brine carrier fluid, a biopolymer suspension agent forincreasing the viscosity of the weighted brine carrier fluid, aparticulate polymetaphosphate composition, and a fluid loss controladditive. At least one opening in the gravel pack screen is plugged withthe particulate polymetaphosphate composition. The fluid loss controlagent then plugs at least one gap between the particles of theparticulate polymetaphosphate composition or a gap between theparticulate polymetaphosphate composition and the gravel pack screenwith the fluid loss control additive. Once the openings are plugged andsealed, one or more additional operations using a fluid in thesubterranean formation can be performed, wherein the fluid is not lostthrough the plugged openings of the gravel pack screen. Once theoperations are completed, the openings can be unplugged by circulatingan aqueous acidic fluid through the wellbore to selectively remove theparticulate polymetaphosphate composition and the fluid loss controladditive. Fluids can then flow through the now un-plugged openings inthe gravel pack screen.

Any of the above, wherein the weighted brine carrier fluid comprises anaqueous fluid and a salt selected from the group consisting of calciumchloride, calcium bromide, zinc bromide, sodium chloride, sodiumbromide, potassium chloride, ammonium chloride, cesium formate, orcombinations thereof.

Any of the above, wherein the biopolymer suspension agent is xanthan,cellulose derivatives, guar derivatives, diutan, or combinationsthereof.

Any of the above, wherein the particulate polymetaphosphate compositionhas the chemical formula of M_(X)P_(X)O_(3X), M″_(X)(P_(X)O_(3X))₂,(M_(Z)M′_((1-Z))PO₃)_(n), or (M_(Z)M″_((1-Z/2))PO₃)_(n), wherein M andM′ are selected from Li, Na, K, Rb, Cs or combinations thereof, M″ isselected from Be, Mg, Ca, Sr, Ba, Zn, Pb, Cu, Ni, or combinationsthereof; X is an integer; Z is 1, ⅔, ½, or ⅓; and, n is an integer from1 to 100, or greater.

Any of the above, wherein the particulate polymetaphosphate compositionis selected from a group comprising sodium polymetaphosphate ((NaPO₃)₆),sodium trimetaphosphate ((NaPO₃)₃), potassium polymetaphosphate((KPO₃)₆), potassium trimetaphosphate ((KPO₃)₃), magnesiumpolymetaphosphate (Mg(PO₃)₂), calcium polymetaphosphate (Ca(PO₃)₂), andcombinations thereof.

Any of the above, wherein the particulate polymetaphosphate compositionhas the general formula of:

AYH₂PO₄.2H₂O+BQO+2(NH₄)₂HPO₄->(1/n)[YQ(PO₃)₃]_(n)+ammonia+water,

wherein A and B are numbers of moles of reactants and the ratio of A:Bis in the range of from about 1:1 to about 6:1, Y is selected from Li,Na, K, Rb, Cs, or combinations thereof, Q is selected from Be, Mg, Ca,Sr, Ba, Zn, Pb, Cu, Ni, or combinations thereof; and, n is from about 1to about 100 or greater. In various embodiments herein, the generalformula of the particulate polymetaphosphate composition indicates apolymetric formula.

Any of the above, wherein the particulate polymetaphosphate compositionhas the formula of:

4YH₂PO₄.2H₂O+QO+2(NH₄)₂HPO₄->(1/n)[Y₄Q(PO₃)₆]_(n)+4NH₃+15H₂O;

2YH₂PO₄.2H₂O+QO+2(NH₄)₂HPO₄->(1/n)[Y₂Q(PO₃)₄]_(n)+4NH₃+9H₂O; or,

YH₂PO₄.2H₂O+QO+2(NH₄)₂HPO₄->(1/n)[YQ(PO₃)₃]_(n)+4NH₃+6H₂O,

wherein A and B are numbers of moles of reactants and the ratio of A:Bis in the range of from about 1:1 to about 6:1, Y is selected from Li,Na, K, Rb, Cs, or combinations thereof, Q is selected from Be, Mg, Ca,Sr, Ba, Zn, Pb, Cu, Ni, or combinations thereof; and, n is from about 1to about 100, or greater.

Any of the above, wherein the particulate polymetaphosphate compositionhas a particle size between about 1 to about 1200 microns.

Any of the above, wherein the particulate polymetaphosphate compositionhas a particle size between about 1 to about 90 microns for plugging anopening in a formation rock and/or wellbore.

Any of the above, wherein the particulate polymetaphosphate compositionhas a particle size between about 200 to 600 microns for plugging anopening in a gravel screen pack.

Any of the above, wherein the fluid loss control additive is selectedfrom a group comprising starch, ground guar, soft wax, oil soluble resinor combinations thereof.

Any of the above, wherein the weighted brine carrier fluid in thetreatment fluid is weighted by a salt selected from the group consistingof calcium chloride, calcium bromide, zinc bromide, sodium chloride,sodium bromide, potassium chloride, ammonium chloride, cesium formate,or combinations thereof; wherein the biopolymer suspension agent fluidin the treatment fluid is present in an amount between 10 to about 120pounds per 1000 gallons of the carrier fluid; wherein the particulatepolymetaphosphate composition fluid in the treatment fluid is present inan amount of about 10 to about 200 pounds per barrel of the carrierliquid, wherein the particulate polymetaphosphate composition has aparticle size between about 1 to about 1200 microns or from about 1 to90 microns or from about 200 to 600 microns; and wherein the fluid losscontrol additive is present in an amount of about 1 to about 20 poundsper barrel of the carrier fluid.

Any of the above treatment fluids further comprising at least oneadditional additive selected from a group comprising salts, pH controladditives, surfactants, breakers, biocides, additional fluid losscontrol agents, stabilizers, chelating agents, scale inhibitors, gases,mutual solvents, particulates, binders, proppants, corrosion inhibitors,oxidizers, reducers, and any combination thereof, wherein the at leastone additional additive does not now the pH of the treatment fluid.

While multiple embodiments are disclosed, still other embodiments willbecome apparent to those skilled in the art from the following detaileddescription. As will be apparent, certain embodiments, as disclosedherein, are capable of modifications in various aspects, withoutdeparting from the spirit and scope of the claims as presented herein.Accordingly, the drawings and detailed description are to be regarded asillustrative in nature and not restrictive.

Definitions

As used herein, the term “treatment,” or “treating,” is intended torefer to any wellbore or subterranean operation that uses a fluid inconjunction with a desired function and/or for a desired purpose. Theterm “treatment,” or “treating,” is not intended to imply any particularaction by the fluid. A “completion fluid” is a type of treatment fluidused during the completion of an oil or gas well, and is used tominimize formation damage and to control formation pressure.

As used herein, the term “fluid loss” refers to the undesirablemigration or loss of fluids into a subterranean formation and/or aproppant pack.

The term “polymetaphosphate” refers to a class of cyclic condensedphosphate-based compounds formed by each phosphate (PO₄) unit sharingtwo corners (i.e. oxygens) with another phosphate unit.Polymetaphosphates are glassy solids that are insoluble or slowlydegradable in water and aqueous fluids, but dissolve readily in acidicfluids with a pH of 4 or less.

All concentrations herein are by weight percent (“wt %”) unlessotherwise specified.

The use of the word “a” or “an” when used in conjunction with the term“comprising” in the claims or the specification means one or more thanone, unless the context dictates otherwise.

The term “about” means the stated value plus or minus the margin oferror of measurement or plus or minus 10% if no method of measurement isindicated.

The use of the term “or” in the claims is used to mean “and/or” unlessexplicitly indicated to refer to alternatives only or if thealternatives are mutually exclusive.

The terms “comprise”, “have”, “include” and “contain” (and theirvariants) are open-ended linking verbs and allow the addition of otherelements when used in a claim.

The phrase “consisting of” is closed, and excludes all additionalelements.

The phrase “consisting essentially of” excludes additional materialelements, but allows the inclusions of non-material elements that do notsubstantially change the nature of the invention.

The following abbreviations are used herein:

ABBREVIATION TERM pptg pounds per thousand gallons ppg pounds pergallons

BRIEF DESCRIPTION OF THE DRAWINGS

The FIGURE displays one embodiment of the presently disclosed methods.

DESCRIPTION OF EMBODIMENTS OF THE DISCLOSURE

The presently disclosure provides novel compositions for wellborecompletion and workover operations, particularly for wellborespenetrating a subterranean formation. The novel treatment fluidcomposition utilizes a polymetaphosphate and a fluid loss controladditive to temporarily seal an opening in a wellbore communicating witha subterranean formation to enable completion or workover operations tobe performed. The polymetaphosphate fills the opening and/or provides abridge on the face of the opening, and the fluid loss control additiveprovides a bridge onto the polymetaphosphate composition thus sealingthe opening. Once the completion or workover operations are finished,the polymetaphosphate can be removed by contact with an acidiccomposition, thus allowing fluid flow. Methods of using the novelcomposition are also described.

In more detail, the novel completion fluid is a weighted degradablecomposition that has a particulate polymetaphosphate composition, abiopolymer suspension agent, a fluid loss control additive, and aweighted brine.

The base of the novel completion fluid is a weighted brine made viscousby the addition of a biopolymer suspension agent. Completion fluids haveto be weighted so the hydrostatic head of the weighted completion fluidwithin a wellbore exerts a greater pressure on the subterraneanformation than the fluid pressures within the formation. The novelcompletion fluid disclosed herein can include a weighted fluid formed byadding any weighting additive used in completions fluids, including butnot limited to, calcium chloride, calcium bromide, zinc bromide, sodiumchloride, sodium bromide, potassium chloride, ammonium chloride, andcesium formate to an aqueous solution.

A biopolymer suspension agent is then added to the weighted brine toincrease the viscosity of the brine, thus creating the carrier fluid forthe completion fluid. The novel completion fluid disclosed hereinincludes any biopolymer suspension agent used in completions fluids,such as xanthan, cellulose derivatives, guar derivatives, diutan, orcombinations thereof. The choice of biopolymer suspension agent willdepend on the downhole conditions. For example, a biopolymer suspensionagent that is stable at extreme temperatures is needed to increase theviscosity of the completion fluid being injected into high temperaturereservoirs. Diutan, which is a high molecular weight gum with goodrheological properties, is stable at higher temperatures. In contrast,xanthan has properties that are more conducive to low to mid-temperaturereservoirs.

The biopolymer suspension agent is present in an amount in the range offrom about 10 to about 120 pounds per 1000 gallons of carrier fluid, oran amount in the range of from about 20 to 60 pounds per 1000 gallons ofcarrier fluid. In some embodiments, the amount of the biopolymersuspension agent is between about 10 to about 50 pounds per 1000 gallonsof carrier fluid, or between about 80 to about 120 pounds per 1000gallons of carrier fluid, or between about 60 to about 80 pounds per1000 gallons of carrier fluid.

Once the carrier fluid has the right viscosity and weight, the fluidloss control agents can be added. At least two types of fluid losscontrol agents are used: a larger material to plug or bridge the face ofthe opening, and a smaller material to bridge the gaps betweenparticulates of the larger material or the gaps between the largermaterial and the edges of the opening.

The predominant fluid loss control agent in the present completionsfluids is a particulate polymetaphosphate composition that is largeenough to bridge the face of the opening or plug the openings.Polymetaphosphates are a class of compounds formed by the cycliccondensation of three or more phosphate groups. Each phosphate unit inthe compound shares two corners with another phosphate unit. Theresulting particulate is a glass solid that is poorly soluble in waterbut readily dissolves in acid.

The completion fluids can utilize particulate polymetaphosphatecompositions that have chemical formulas selected from a groupconsisting of M_(X)P_(X)O_(3X), M″_(X)(P_(X)O_(3X))₂,(M_(Z)M′_((1-Z))PO₃)_(n), or (M_(Z)M″_((1-Z/2))PO₃)_(n), wherein M andM′ are selected from Li, Na, K, Rb, Cs, or combinations thereof, M″ isselected from Be, Mg, Ca, Sr, Ba, Zn, Pb, Cu, Ni, or combinationsthereof; X is an integer; Z is 1, ⅔, ½, or ⅓; and, n is from about 1 toabout 100 or greater.

Exemplary particulate polymetaphosphate compositions for use in thepresent fluids includes sodium polymetaphosphate ((NaP₃)₆), sodiumtrimetaphosphate ((NaPO₃)₃), potassium polymetaphosphate ((KPO₃)₆),potassium trimetaphosphate ((KPO₃)₃), magnesium polymetaphosphate(Mg(PO₃)₂), calcium polymetaphosphate (Ca(PO₃)₂), Slow Phos® (PacificStandard Specialties, Mesa, AZ), PolyPhos® (SPER Chemical Company,Clearwater, Fla.), and combinations thereof.

Additional polymetaphosphates compositions are described inUS20160069155, which is incorporated herein in its entirety for allpurposes. US20160069155 teaches the use of polymetaphosphatescompositions for forming solid masses such as tools or spherical shapes,which are then coated to prevent hydration of the polymetaphosphatescompositions. The present methods utilize polymetaphosphatescompositions with addition fluid loss control agents to fill gapsbetween the polymetaphosphates particles as well as weighting chemicalsto move the fluid loss control agents through the reservoir.

The polymetaphosphate compositions in US20160069155 are formed by thefollowing chemical reaction of:

AYH₂PO₄.2H₂O+BQO+2(NH₄)₂HPO₄->(1/n)[YQ(PO₃)₃]_(n)+ammonia+water,

wherein A and B are numbers of moles of reactants and the ratio of A:Bis in the range of from about 1:1 to about 6:1. Exemplary chemicalreactions include:

4YH₂PO₄.2H₂O+QO+2(NH₄)₂HPO₄->(1/n)[Y₄Q(PO₃)₆]_(n)+4NH₃+15H₂O;

2YH₂PO₄.2H₂O+QO+2(NH₄)₂HPO₄->(1/n)[Y₂Q(PO₃)₄]_(n)+4NH₃+9H₂O; or,

YH₂PO₄.2H₂O+QO+2(NH₄)₂HPO₄->(1/n)[YQ(PO₃)₃]_(n)+4NH₃+6H₂O,

wherein A and B are numbers of moles of reactants and the ratio of A:Bis in the range of from about 1:1 to about 6:1, Y is selected from Li,Na, K, Rb, Cs, or combinations thereof, Q is selected from Be, Mg, Ca,Sr, Ba, Zn, Pb, Cu, Ni, or combinations thereof, and, n is from about 1to about 100 or greater. The following article provides a description ofpolymetaphosphate compositions and along with their synthesis andcharacterization, Mehrotra, Ram C. “Synthesis and properties of simpleand complex polymetaphosphate glasses of alkali metals.” Pure andApplied Chemistry 44 (1975): 201-220, the contents of which areincorporated herein by reference in its entirety.

As described in US20160069155, particulate polymetaphosphatecompositions may be formulated to have a predetermined solubility in theformation or carrier fluid. This enables the composition to besubstantially insoluble for a period of time and then experiencecontrolled degradation in the subterranean formation, wherein it isslowly degradable in aqueous fluid present in the formation under theconditions existing in the subterranean formation. Thus, the operatorcan controllably block certain porous rock or other areas in a reservoirfor a temporary period of time, without having to worry about permanentblockage.

Though dissolvable, the particulate material is substantially apolymetaphosphate composition that should be insoluble in and suspendedby the carrier fluid. For the present fluids and methods, the weightedbrine carrier fluid allows the particulate polymetaphosphate compositionto remain substantially insoluble in the formation until the carrierfluid is removed, by e.g. circulation of an aqueous fluid within thewellbore or the introduction of an aqueous acidic solution. After thecarrier fluid is removed, the particulate polymetaphosphate compositioncan rapidly be dissolved. This results in the fluid loss to theformation to greatly increase, assisting in the removal of any remainingcomposition constituents in the perforation or formation.

The particulate polymetaphosphate composition has a particle size thatis selected such that it plugs or bridges on the face of the openingand/or fill the perforation or opening. Thus, the particulatepolymetaphosphate composition has a particle size in the range of fromabout 1 to about 1200 microns. In some embodiments, the particle size inthe range of from about 1 to about 90 microns, when the surface to bebridged is a formation face. In other embodiments, the particle size inthe range of from about 10 to about 600 microns when the surface beingbridged is a gravel pack screen. Alternatively, the particle size isbetween about 1 micron to 130 microns, or between about 750 microns toabout 1200 microns, or between about 200 microns to about 600 microns.

Further, the particulate polymetaphosphate composition is present in thecarrier fluid in an amount of from about 10 to about 200 pounds perbarrel of the carrier fluid. Alternatively, the particulatepolymetaphosphate composition is present in an amount between about 10and 75 pounds per barrel of the carrier liquid, or between about 125 and200 pounds per barrel of the carrier liquid, or between about 75 and 125pounds per barrel of the carrier liquid.

A second, smaller particulate material can be added to the novelcompletion fluid as a fluid loss control additive. The smalleradditional fluid loss control material has a particle size selected suchthat it bridges on the larger polymetaphosphate particulates and forms aseal thereover.

Any fluid loss control additive typically used in completions fluids canbe used as the second particulate material. Examples of such additionalfluid loss control agents include, but are not limited to, starchespolylactic acid, polyglycolic acid, other aliphatic esters, silicaflour, gas bubbles (energized fluid or foam), benzoic acid, soaps, resinparticulates, relative permeability modifiers, and other immisciblefluids. In some embodiments, the fluid control additive is selected froma group comprising starch, ground guar, soft wax, oil soluble resin orthe like.

The second particulate solid material have a median particle size whichis about ⅓ the median size of the openings between the particulatepolymetaphosphate composition to bridge thereon. Ranges of particlesizes for the second particulate solid material is between about 0.01 toabout 100 microns or between about 3 and 100 microns. In someembodiments, the additional fluid loss control material is present inthe range of from about 1 to about 20 pounds per barrel of the carrierfluid.

After mixing the fluid loss control agents into the viscous, weightedbrine, the novel completion fluid can be injected into a reservoir totemporarily seal a wellbore communicating with a subterranean formationto enable completion or workover operations to be performed. Once thefluid loss control capabilities are not needed, the composition can beremoved by contact with an acidic composition circulating through thewellbore.

Depending on the application of the completion fluid, additionaladditives that do not lower the pH of the fluid can be included in thecarrier fluid to address other needs of the reservoir or wellborewithout affecting the ability of the polymetaphosphate composition andfluid loss control additive to form a physical barrier. Thus, thecompletion fluids can further comprise optional additive including, butnot limited to salts, pH control additives, surfactants, breakers,biocides, additional fluid loss control agents, stabilizers, chelatingagents, scale inhibitors, gases, mutual solvents, particulates,corrosion inhibitors, oxidizers, reducers, and any combination thereof.In some embodiments, the additives are added after the openings havebeen blocked by the polymetaphosphate composition and fluid loss controladditive.

In more detail, the novel completion fluid compositions can be combinedwith optional additives such as:

Particulates

The novel completion fluids described herein may further compriseadditional optional particulates, including proppant particulates orgravel particulates. Such particulates may be included in the completionfluids when, for example, a gravel pack is to be formed in at least aportion of the wellbore, or a proppant pack is to be formed in one ormore fractures in the subterranean formation.

Particulates for use in the presently described completion fluids andmethods may comprise any material used in subterranean operations,including but not limited to, sand, bauxite, ceramic materials, glassmaterials, polymer materials, polytetrafluoroethylene materials, nutshell pieces, cured resinous particulates comprising nut shell pieces,seed shell pieces, cured resinous particulates comprising seed shellpieces, fruit pit pieces, cured resinous particulates comprising fruitpit pieces, wood, composite particulates, and combinations thereof.Exemplary composite particulates may comprise a binder and a fillermaterial wherein the filler materials include silica, alumina, fumedcarbon, carbon black, graphite, mica, titanium dioxide, calciumsilicate, kaolin, talc, zirconia, boron, fly ash, hollow glassmicrospheres, solid glass, and combinations thereof.

The additional particulates described here are not limited to aparticular shape. All shapes of materials, including sphericalmaterials, fibrous materials, polygonal materials (such as cubicmaterials), and mixtures thereof can be used according to theapplication. For example, fibrous materials may or may not be used tobear the pressure of a closed fracture during a fracturing operation,but could be included in the fluid loss control operations. In someembodiments, the particulates may be coated with any suitable resin ortackifying agent known to those of ordinary skill in the art.

The mean particulate size for these additional particulates may rangefrom about 2 mesh to about 400 mesh on the U.S. Sieve Series Scale.However, in certain circumstances, other mean particulate sizes may bedesired and will be entirely suitable for practice of the presentlydescribed methods. In some embodiments, the mean particulate sizedistribution ranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40,30/50, 40/60, 40/70, 50/70, or 70/140 mesh, or down to smaller sizes of200 mesh and 10's of microns. The additional particulates may be presentin the completion fluids in the range of from about 0.5 pounds pergallon (“ppg”) to about 30 ppg by volume of the completion fluid.

pH Control

A pH control additive may be necessary to maintain the pH of thecompletion fluid at a desired level to improve the effectiveness ofcertain breakers or crosslinkers. One of ordinary skill in the art willbe able to select a pH for a particular application.

Surfactants

In some embodiments, the completion fluids of the present disclosure mayinclude optional surfactants to improve the compatibility of thecompletion fluids with other fluids (like any formation fluids) that maybe present in the wellbore. One of ordinary skill in the art will beable to identify the type of surfactant as well as the appropriateconcentration of surfactant to be used.

Surfactants may be used in a liquid or powder form. Where used, thesurfactants may be present in the completion fluid in an amountsufficient to prevent incompatibility with formation fluids, othercompletion fluids, or wellbore fluids. In an embodiment where liquidsurfactants are used, the surfactants are present in the range of fromabout 0.01% to about 5.0% by volume of the completion fluid. In otherembodiments, the liquid surfactants are present in the range of fromabout 0.1% to about 2.0% by volume of the completion fluid. In otherembodiments, the liquid surfactants are present in the range of fromgreat than 0 to about 10 pptg of the carrier fluid, or about 2 to about7 pptg of the carrier fluid or 1 pptg of the carrier fluid. Inembodiments where powdered surfactants are used, the surfactants may bepresent in the range of from about 0.001% to about 0.5% by weight of thecompletion fluid.

In those embodiments where it is desirable to foam the completion fluidsof the present disclosure, surfactants such as HY-CLEAN (HC-2)surface-active suspending agent or AQF-2 additive, both commerciallyavailable from Halliburton Energy Services, Inc., of Duncan, Okla., maybe used. Additional examples of foaming agents that may be used to foamand stabilize the completion fluids include, but are not limited to,betaines, amine oxides, methyl ester sulfonates, alkylamidobetaines suchas cocoamidopropyl betaine, alpha-olefin sulfonate, trimethyl tallowammonium chloride, C8 to C22 alkylethoxylate sulfate and trimethyl cocoammonium chloride. Other foaming agents and foam stabilizing agents maybe included as well, which will be known to those skilled in the art.

Breakers

In some embodiments of the present disclosure, the completion fluids maycomprise breakers.

Examples of breakers for use in the described completion fluids include,but are not limited to, sodium chlorites, hypochlorites, perborate,persulfates, and peroxides (including organic peroxides). Other breakersinclude, but are not limited to, acids and peroxide breakers, delinkers,as well as enzymes that may be effective in breaking viscosifiedcompletion fluids. In some embodiments, the breaker may be citric acid,tetrasodium EDTA, ammonium persulfate, or cellulose enzymes.

A breaker may be included in an amount and form sufficient to achievethe desired viscosity reduction at a desired time. The breaker may beformulated to provide a delayed break or may be encapsulated.Encapsulation methods are known by those skilled in the art, andexemplary encapsulation methods involve coating the selected breaker ina porous material that allows for release of the breaker at a controlledrate, or coating the chosen breakers with a material that will degradewhen downhole so as to release the breaker when desired. Resins that maybe useful in the present compositions include, but are not limited to,polymeric materials that will degrade when downhole.

Alternatively, the breakers may be encapsulated by synthetic and naturalwaxes. Waxes having different melting points may be used in order tocontrol the delay of breaking based on the temperature of a specificsubterranean operation. The encapsulation of the breaker is performed bymixing the breaker and wax above the melting temperature for thespecific wax and then extruding the composition to form small particlesof the encapsulated material. The resulting product may be annealed bybriefly heating the product to the point of the coating to seal cracksin the coating, thus preventing premature release. The encapsulation mayalso be achieved by melt spraying the wax on the breaker (for example,citric acid) particles or by any other technique known by one ofordinary skill in the art. If used, a breaker should be included in thedisclosed completion fluid in an amount sufficient to facilitate thedesired reduction in viscosity in the weighted brine. For instance,peroxide concentrations that may be used vary from about 0.1 to about 30gallons of peroxide per 1000 gallons of the completion fluid. Similarly,for instance, when citric acid is used as a breaker, concentrations offrom 0.11 pptg to 30 pptg are appropriate.

An optional activator or retarder to can be used to, among other things,optimize the break rate provided by a breaker. Any known activator orretarder that is compatible with the selected breaker can be used in thepresent completion fluids. Examples of activators include, but are notlimited to, acid generating materials, chelated iron, copper, cobalt,and reducing sugars. Examples of retarders include sodium thiosulfate,methanol, and diethylenetriamine. One of ordinary skill will be able toidentify an activator or retarder for use with the selected breaker, andthe proper concentration of such activator or retarder for a givenapplication.

In some embodiments, the retarder or activator may be used in a range offrom about 1 to about 100 pptg of carrier fluid or from about 5 to about20 pptg.

One of ordinary skill will be able to identify an activator or retarderfor use with the selected breaker, and the proper concentration of suchactivator or retarder for a given application.

Fluid Loss Control Additives

In some embodiments of the presently described completion fluids,additional fluid loss control additives may be combined withpolymetaphosphate composition and the fluid loss control additivespreviously described herein. Examples of such additional fluid losscontrol agents include, but are not limited to, starches (such asIN-DRIL® HT Plus, commercially available from Halliburton EnergyServices, Inc. of Duncan, Okla.), polylactic acid, polyglycolic acid,other aliphatic esters, silica flour, gas bubbles (energized fluid orfoam), benzoic acid, soaps, resin particulates, relative permeabilitymodifiers, and other immiscible fluids. If included, the additionalfluid loss additive may be included in an amount of about 5 to about2000 pptg of the completion fluid.

Corrosion Inhibitors

In some embodiments of the presently described completion fluids,corrosion inhibitors may be combined with the polymetaphosphatecomposition and fluid loss control additive. Corrosion inhibitors aremixed with the completion fluid to protect the metal components thefluid is likely to contact. It is especially useful in acid treatmentsto protect iron and steel components in the wellbore and treatingequipment from the corrosive treating fluid.

Corrosion inhibitor activators, such as quaternary ammonium compounds,are added to activate the corrosion inhibitors components. Examples ofcorrosion inhibitor activators which can be utilized in accordance withthe present completion fluids include, but are not limited to, coppercompounds such as cuprous iodide and cuprous chloride; antimonycompounds such as antimony oxides, antimony halides, antimony tartrate,antimony citrate, alkali metal salts of antimony tartrate and antimonycitrate, alkali metal salts of pyroantimonate and antimony adducts ofethylene glycol; bismuth compounds such as bismuth oxides, bismuthhalides, bismuth tartrate, bismuth citrate, alkali metal salts ofbismuth tartrate and bismuth citrate; iodine; iodide compounds; formicacid and combinations thereof. When a corrosion inhibitor activator isincluded in the completion fluid, it can be present in the range of fromabout 0.1 wt % to about 5.0 wt % of the completion fluid.

Because of the polymetaphosphate composition and fluid loss controladditive's ability to be combined with a variety of known oil and gascompletion fluid additives without adverse effects to thepolymetaphosphate composition and fluid loss control additive's physicalblocking abilities, the polymetaphosphate composition and fluid losscontrol additive can be used in a variety of applications. Itsversatility will allow the present composition to be used for manydifferent operations, including fluid loss control, diversion, andplugging operations.

The present compositions and methods are exemplified with respect to thefollowing description for a wellbore that penetrates a subterraneanformation, and The FIGURE. However, this is exemplary only, and thecompositions and methods can be broadly applied to any combination ofparticulate polymetaphosphate composition, a biopolymer suspensionagent, a smaller fluid loss control additive, and a weighting fluid. Thefollowing is intended to be illustrative only, and not unduly limit thescope of the appended claims.

In The FIGURE, a wellbore 10 is drilled through a hydrocarbon containingformation 12. Per known methods, the wellbore 10 is completed with acasing or liner disposed therein, wherein a cement slurry is pumped intothe well to displace the existing drilling fluids and fill in the spacebetween the casing and the actual sides of the drilled well. Thisresults in a cement sheath that surrounds the casing in the annulusbetween the casing and the formation 12. The cement sheath bonds thecasing to the walls of the formation and prevents fluids from flowingbehind the casing.

To establish a path between the wellbore and the formation 12,perforation operations are performed to create at least one perforation14 in the wellbore. The perforation 14 can be created using knownmethods, such as e.g. shaped explosive charges on a perforation gun.

Once at least one perforation 14 establishes communication between thewellbore 10 and the formation 12, a high density completion fluid suchas the novel completion fluid described here can be injected throughwellbore 10 and pumped down the tubing 16. The particulatepolymetaphosphate composition and smaller fluid loss control additiveare carried through the wellbore 10 by the viscous, weighted carrierfluid. Thus, a slurry of particulate solid material flows through theperforation 14 into the formation 12.

The particulate polymetaphosphate composition bridges on the face of theformation 12 and fills the cavity or tunnel of the perforations 14. Eventhough the perforations 14 are bridged with the polymetaphosphatecomposition, liquid from the interior of the casing can continue to flowthrough the porosity of the particulate solid material and into theformation 12. This continued fluid loss can be reduced by the second,smaller fluid loss control material in the carrier fluid. The additionalfluid loss control particulate solid material bridges on the particulatepolymetaphosphate composition to form a seal over the opening of theperforations 14 within the interior of the casing. As mentioned above,the size of this additional fluid loss control particulate solidmaterial is about a third of the size of the particulatepolymetaphosphate composition.

The wellbore 10 normally contains a plurality of perforations 14, all ofwhich are filled with the particulate polymetaphosphate composition andthe second fluid loss particulate material at the same time. Once theperforations are sealed, any desired operations may be performed withinthe wellbore 10 such as tripping perforating guns out of the wellboreafter perforating, making up and running into the wellbore a screenassembly, coming out of a wellbore with a service tool, running acompletion assembly or the like.

Upon completion of the well operations, the fluid loss control materialscan be removed from the wellbore 10, the perforations 14 and theformation 12, by an aqueous acidic fluid circulated down the tubing 16and upwardly in the annulus between the tubing 18 and the casing. Theaqueous acidic fluid dissolves the smaller fluid loss material withinthe casing. When the smaller fluid loss material is dissolved to thepoint where it no longer seals the perforations 14, the aqueous acidicfluid flows into the perforations 14 by way of the porosity of theparticulate polymetaphosphate composition. The aqueous acidic fluidcontinues to flow through the perforation 14 and into the formation 12whereby the particulate polymetaphosphate composition is also dissolvedand all of the particulate solid material is removed.

Variations of the above methods can be made to address differentopenings. When openings in a gravel pack screen positioned within awellbore need to be sealed, the viscous fluid can be introduced into theinside of a gravel pack screen. Similar to the above embodiment forpacking a perforation, the particulate polymetaphosphate composition andsecond particulate material can be used to close openings. However,larger particle sizes of both particulate materials will be needed dueto the larger opening in the gravel pack. Once the screen surface hasbeen sealed, other operations can be performed in the wellbore.

Thus, the present compositions are capable of blocking and/or fillingopenings in formations for temporary periods of time under a variety ofreservoir conditions without the risk of permanent blockage. This allowsfor completion operations to be performed and finish without the loss offluids to the formation. The openings can then be quickly unpluggedthrough the use of acidic fluids that readily dissolve fluid losscontrol agents in a matter of minutes without damaging the formation.

The following references are incorporated by reference in theirentirety.

US20160069155

1. A completion fluid comprising: a) a weighted brine; b) a biopolymersuspension agent for increasing the viscosity of said weighted brine toform a carrier fluid; c) a particulate polymetaphosphate composition;and, d) a fluid loss control additive.
 2. The completion fluid of claim1, further comprising salts, pH control additives, surfactants,breakers, biocides, additional fluid loss control agents, stabilizers,chelating agents, scale inhibitors, gases, mutual solvents,particulates, binders, proppants, corrosion inhibitors, oxidizers,reducers, or combinations thereof.
 3. The completion fluid of claim 1,wherein said weighted brine comprises an aqueous fluid and a saltselected from the group consisting of calcium chloride, calcium bromide,zinc bromide, sodium chloride, sodium bromide, potassium chloride,ammonium chloride, cesium formate, or combinations thereof.
 4. Thecompletion fluid of claim 1, wherein said biopolymer suspension agent isxanthan, cellulose derivatives, guar derivatives, diutan, orcombinations thereof.
 5. The completion fluid of claim 1, wherein saidpolymetaphosphate composition has a formula selected from a groupcomprising M_(X)P_(X)O_(3X), M″_(X)(P_(X)O_(3X))₂,(M_(Z)M′_((1-Z))PO₃)_(n), or (M_(Z)M″_((1-Z/2))PO₃)_(n), wherein M andM′ are selected from Li, Na, K, Rb, Cs or combinations thereof; M″ isselected from Be, Mg, Ca, Sr, Ba, Zn, Pb, Cu, Ni, or combinationsthereof; X is an integer; Z is 1, ⅔, ½, or ⅓; and, n is an integer from1 to
 100. 6. The completion fluid of claim 1, wherein saidpolymetaphosphate composition has the formula of:AYH₂PO₄.2H₂O+BQO+2(NH₄)₂HPO₄->(1/n)[YQ(PO₃)₃]_(n)+ammonia+water whereinA and B are numbers of moles of reactants and the ratio of A:B is in therange of from about 1:1 to about 6:1, Y is selected from Li, Na, K, Rb,Cs, or combinations thereof, Q is selected from Be, Mg, Ca, Sr, Ba, Zn,Pb, Cu, Ni, or combinations thereof, and n is from about 1 to about 100.7. The completion fluid of claim 6, wherein said polymetaphosphatecomposition has the formula of:4YH₂PO₄.2H₂O+QO+2(NH₄)₂HPO₄->(1/n)[Y₄Q(PO₃)₆]_(n)+4NH₃+15H₂O;2YH₂PO₄.2H₂O+QO+2(NH₄)₂HPO₄->(1/n)[Y₂Q(PO₃)₄]_(n)+4NH₃+9H₂O; or,YH₂PO₄.2H₂O+QO+2(NH₄)₂HPO₄->(1/n)[YQ(PO₃)₃]_(n)+4NH₃+6H₂O
 8. Thecompletion fluid of claim 1, wherein said polymetaphosphate compositionhas a particulate polymetaphosphate material with a particle sizebetween about 1 to about 1200 microns.
 9. The completion fluid of claim1, wherein said fluid loss control additive is selected from a groupcomprising starch, ground guar, soft wax, oil soluble resin orcombinations thereof.
 10. The completion fluid of claim 1, wherein a)said weighted brine has a salt selected from the group consisting ofcalcium chloride, calcium bromide, zinc bromide, sodium chloride, sodiumbromide, potassium chloride, ammonium chloride, cesium formate, orcombinations thereof; b) said biopolymer suspension agent is present inan amount between 10 to about 120 pounds per 1000 gallons of the carrierfluid; c) said polymetaphosphate composition is present in an amount of10 to about 200 pounds per barrel of the carrier liquid, wherein aparticulate polymetaphosphate material has a particle size between about1 to about 1200 microns; and d) said fluid loss control additive ispresent in an amount of 1 to about 20 pounds per barrel of the carrierfluid.
 11. A method of plugging an opening in a reservoir comprising: a)injecting into a subterranean formation, a treatment fluid comprising:i) a weighted brine carrier fluid; ii) a biopolymer suspension agent forincreasing the viscosity of said weighted brine carrier fluid; iii) aparticulate polymetaphosphate composition; and, iv) a fluid loss controladditive. b) blocking at least one opening in said subterraneanformation with the particulate polymetaphosphate composition; c)blocking at least one gap between the particles of the particulatepolymetaphosphate composition or a gap between the particulatepolymetaphosphate composition and said opening with the fluid losscontrol additive; d) performing one or more additional operations thatuses a fluid in said subterranean formation, wherein the fluid is notlost through the blocked openings; e) circulating an aqueous acidicfluid through said wellbore to remove the particulate polymetaphosphatecomposition and the fluid loss control additive; and, f) flowing fluidsthrough the unblocked opening.
 12. The method of claim 11, wherein saidopening is in a gravel pack screen.
 13. The method of claim 11, whereinsaid opening is in a vug, a pore space, or fracture.
 14. The method ofclaim 11 wherein said particulate polymetaphosphate composition has aparticle size between about 1 to about 1200 microns.
 15. The method ofclaim 11, wherein said polymetaphosphate composition has a formulaselected from a group comprising M_(X)P_(X)O_(3X), M″_(X)(P_(X)O_(3X))₂(M_(Z)M′_((1-Z))PO₃)_(n) or (M_(Z)M″_((1-Z/2))PO₃)_(n), wherein M and M′are selected from Li, Na, K, Rb, Cs or combinations thereof; M″ isselected from Be, Mg, Ca, Sr, Ba, Zn, Pb, Cu, Ni, or combinationsthereof; X is an integer; Z is 1, ⅔, ½, or ⅓; and, n is from about 1 toabout 100 or greater.
 16. The method of claim 11, wherein saidpolymetaphosphate composition is selected from a group comprising sodiumpolymetaphosphate ((NaPO₃)₆), sodium trimetaphosphate ((NaPO₃)₃),potassium polymetaphosphate ((KPO₃)₆), potassium trimetaphosphate((KPO₃)₃), magnesium polymetaphosphate (Mg(PO₃)₂), calciumpolymetaphosphate (Ca(PO₃)₂), and combinations thereof.
 17. The methodof claim 11, wherein said polymetaphosphate composition has the generalformula of:AYH₂PO₄.2H₂O+BQO+2(NH₄)₂HPO₄->(1/n)[YQ(PO₃)₃]_(n)+ammonia+water whereinA and B are numbers of moles of reactants and the ratio of A:B is in therange of from about 1:1 to about 6:1, Y is selected from Li, Na, K, Rb,Cs or combinations thereof, Q is selected from Be, Mg, Ca, Sr, Ba, Zn,Pb, Cu, Ni, or combinations thereof, and n is from about 1 to about 100or greater.
 18. The method of claim 11, wherein said weighted brinecarrier fluid comprises an aqueous fluid and a salt selected from thegroup consisting of calcium chloride, calcium bromide, zinc bromide,sodium chloride, sodium bromide, potassium chloride, ammonium chloride,cesium formate, or combinations thereof.
 19. The method of claim 11,wherein said biopolymer suspension agent is xanthan, cellulosederivatives, guar derivatives, diutan, or combinations thereof.
 20. Themethod of claim 11, wherein said fluid loss control additive is selectedfrom a group comprising starch, ground guar, soft wax, oil soluble resinor combinations thereof.